Certain geological formations are known to contain an organic matter known as “kerogen.” Kerogen is a solid, carbonaceous material. When kerogen is imbedded in rock formations, the mixture is referred to as oil shale. This is true whether or not the mineral is, in fact, technically shale, that is, a rock formed from compacted clay.
Kerogen is subject to decomposing upon exposure to heat over a period of time. Upon heating, kerogen molecularly decomposes to produce oil, gas, and carbonaceous coke. Small amounts of water may also be generated. The oil, gas and water fluids become mobile within the rock matrix, while the carbonaceous coke remains essentially immobile.
Oil shale formations are found in various areas world-wide, including the United States. Oil shale formations tend to reside at relatively shallow depths. In the United States, oil shale is most notably found in Wyoming, Colorado, and Utah. These formations are often characterized by limited permeability. Some consider oil shale formations to be hydrocarbon deposits which have not yet experienced the years of heat and pressure thought to be required to create conventional oil and gas reserves.
The decomposition rate of kerogen to produce mobile hydrocarbons is temperature dependent. Temperatures generally in excess of 270° C. (518° F.) over the course of many months may be required for substantial conversion. At higher temperatures substantial conversion may occur within shorter times. When kerogen is heated, chemical reactions break the larger molecules forming the solid kerogen into smaller molecules of oil and gas. The thermal conversion process is referred to as pyrolysis or retorting.
Attempts have been made for many years to extract oil from oil shale formations. Near-surface oil shales have been mined and retorted at the surface for over a century. In 1862, James Young began processing Scottish oil shales. The industry lasted for about 100 years. Commercial oil shale retorting through surface mining has been conducted in other countries as well such as Australia, Brazil, China, Estonia, France, Russia, South Africa, Spain, and Sweden. However, the practice has been mostly discontinued in recent years because it proved to be uneconomical or because of environmental constraints on spent shale disposal. See, e.g., T. F. Yen, and G. V. Chilingarian, “Oil Shale,” Amsterdam, Elsevier, p. 292, the entire disclosure of which is incorporated herein by reference. Further, surface retorting requires mining of the oil shale, which often limits application to very shallow formations.
In the United States, the existence of oil shale deposits in northwestern Colorado has been known since the early 1900's. While research projects have been conducted in this area from time to time, no serious commercial development has been undertaken. Most research on oil shale production has been carried out in the latter half of the 1900's. The majority of this research was on shale oil geology, geochemistry, and retorting in surface facilities.
In 1947, U.S. Pat. No. 2,732,195 issued to Ljungstrom. The '195 patent, entitled “Method of Treating Oil Shale and Recovery of Oil and Other Mineral Products Therefrom,” described the application of heat at high temperatures to the oil shale formation in situ to distill and produce hydrocarbons. The '195 Ljungstrom patent is incorporated herein by reference. Ljungstrom coined the phrase “heat supply channels” to describe bore holes drilled into the formation. The bore holes received an electrical heat conductor which transferred heat to the surrounding oil shale. Thus, the heat supply channels served as heat injection wells. The electrical heating elements in the heat injection wells were placed within sand or cement or other heat-conductive material to permit the heat injection wells to transmit heat into the surrounding oil shale while preventing the inflow of fluid. According to Ljungstrom, the “aggregate” was heated to between 500° and 1,000° C., in some applications.
Along with the heat injection wells, fluid producing wells were also completed in near proximity to the heat injection wells. As kerogen was pyrolyzed upon heat conduction into the rock matrix, the resulting oil and gas would be recovered through the adjacent production wells. Ljungstrom applied his approach of thermal conduction from heated wellbores through the Swedish Shale Oil Company. A full scale plant was developed that operated from 1944 into the 1950's. See, e.g., G. Salomonsson, “The Ljungstrom In Situ Method for Shale-Oil Recovery,” 2nd Oil Shale and Cannel Coal Conference, v. 2, Glasgow, Scotland, Institute of Petroleum, London, p. 260-280 (1951), the entire disclosure of which is incorporated herein by reference.
Additional in situ methods have been proposed. These methods generally involve the injection of heat and/or solvent into a subsurface oil shale. Heat may be in the form of heated methane (see U.S. Pat. No. 3,241,611 to J. L. Dougan), flue gas, or superheated steam (see U.S. Pat. No. 3,400,762 to D. W. Peacock). Heat may also be in the form of electric resistive heating, dielectric heating, radio frequency (RF) heating (U.S. Pat. No. 4,140,180, assigned to the ITT Research Institute in Chicago, Ill.) or oxidant injection to support in situ combustion. In some instances, artificial permeability has been created in the matrix to aid the movement of pyrolyzed fluids. Permeability generation methods include mining, rubblization, hydraulic fracturing (see U.S. Pat. No. 3,468,376 to M. L. Slusser and U.S. Pat. No. 3,513,914 to J. V. Vogel), explosive fracturing (see U.S. Pat. No. 1,422,204 to W. W. Hoover, et al.), heat fracturing (see U.S. Pat. No. 3,284,281 to R. W. Thomas), and steam fracturing (see U.S. Pat. No. 2,952,450 to H. Purre).
In 1989, U.S. Pat. No. 4,886,118 issued to Shell Oil Company, the entire disclosure of which is incorporated herein by reference. That patent, entitled “Conductively Heating a Subterranean Oil Shale to Create Permeability and Subsequently Produce Oil,” declared that “[c]ontrary to the implications of . . . prior teachings and beliefs . . . the presently described conductive heating process is economically feasible for use even in a substantially impermeable subterranean oil shale.” (col. 6, ln. 50-54). Despite this declaration, it is noted that few, if any, commercial in situ shale oil operations have occurred other than Ljungstrom's application. The '118 patent proposed controlling the rate of heat conduction within the rock surrounding each heat injection well to provide a uniform heat front.
Additional history behind oil shale retorting and shale oil recovery can be found in co-owned U.S. Pat. No. 7,331,385 (Symington) entitled “Methods of Treating a Subterranean Formation to Convert Organic Matter into Producible Hydrocarbons,” and in U.S. Pat. No. 7,441,603 (Kaminsky) “Hydrocarbon Recovery from Impermeable Oil Shales.” The Background and technical disclosures of each these two patent documents are incorporated herein by reference, including for example, for the purposes of incorporating one or more the various heating and treatment methods that may be applicable to the present application.
As described hereinabove, a full scale plant was developed that operated from 1944 into the 1950's. See, e.g., G. Salamonsson, “The Ljungstrom In Situ Method for Shale-Oil Recovery,” 2nd Oil Shale and Cannel Coal Conference, v. 2, Glasgow, Scotland, Institute of Petroleum, London, p. 260-280 (1951). For example, Ljungstrom describes the use of an oil shale development field as a large energy accumulator based on electricity sourced from hydroelectric power. Specifically, because of the low thermal conductivity of the shale, the heat can be stored in the rock for a long time (years). When a period of power or fuel shortage is coming, some additional heat must be supplied for pyrolyzing the shale. Thereby, a considerably higher production may be obtained than would have been possible with the actual power supply (without preheating). Ljungstrom further describes accumulating surplus electrical power, such as surplus hydroelectric power, e.g., at night, or in summer, or in rain-rich years.
In addition, various studies have estimated that greenhouse gas (GHG) emissions associated with in situ conversion processes may be higher than that associated with conventional fossil fuel resources. See, e.g., Brandt, Adam R., “Converting Oil Shale to Liquid Fuels: Energy Inputs and Greenhouse Gas Emissions of the Shell in Situ Conversion Process,” Environ. Sci. Technol. 2008, 42, pp. 7489-7495, the entirety of which is incorporated herein by reference. For example, Brandt suggests that in the absence of capturing CO2 generated from electricity produced to fuel the process, well-to-pump GHG emissions may be in the range of 30.0-37.0 grams of carbon equivalent per megajoule of liquid fuel produced in the described In Situ Conversion Process (ICP). Brandt suggests that these full-fuel-cycle emissions are 21%-47% larger than those from conventionally produced petroleum-based fuels.
For example, Brandt suggests that if electricity were generated from low carbon sources (such as renewables or fossil fuels with carbon capture), then emissions from oil shale would be approximately equal to those from conventional oil. Referring to FIG. 29 of the present application, which is based on analysis conducted by Brandt, several differences between conventional oil, a high GHG emissions estimate of the ICP process, and a low GHG emissions estimate of the ICP process. FIG. 29 depicts a chart 2900 of estimated greenhouse gas emissions in units of grams of Carbon equivalent per Megajoule of refined fuel, e.g., the at the pump product. Data for the high ICP case 2910, the low ICP case 2920, and a comparative conventional oil process 2930 are shown. GHG emissions associated with retorting, reclamation, the ICP freezewall process, and miscellaneous production, transportation, and refining processes are shown for each of the exemplary processes. It will be further appreciated that a significant portion of the increase in GHG emissions associated with the ICP process is associated with the energy required to retort (GHG associated with electrical power generation for heaters), support the freeze walls, and/or for reclamation associated with shale oil production activities, such as flushing the formation during or after production. In fact, as seen in FIG. 29 and suggested by Brandt, if the GHG emissions associated with retorting, reclamation, and/or mitigations steps (such as freezewalls) are reduced, if not eliminated, the potential exists for the overall GHG emissions associated with in situ conversion processes to be reduced below that of conventional oil.
Brandt also suggests, as previously identified by Ljungstrom, that the energy requirements of in situ electrically conductive heaters, such as the ICP process, are likely to not be sensitive to intermittency, because of the high heat capacity of the large mass of shale and the long heating time. Thus, intermittent renewables could be used in off-peak times. Second, the reuse of waste heat seems feasible, given that the hot, depleted production cells will need to be flushed with water to meet the water quality requirements in any case. However, these low-carbon ICP options are costly and, therefore, are unlikely without regulation of carbon emissions. The present inventors have determined that there are several ways in which intermittent renewables may be selectively deployed in hydrocarbon recovery processes, such as in situ heating of oil shale, tar sands, or other heavy hydrocarbons, in a manner that does not necessarily require the regulation of carbon emissions to achieve cost reductions that ensure one or more of the in situ heating processes referred to in this description remain competitive with conventional oil, e.g., similar in costs and environmental footprint.
U.S. Pat. No. 7,484,561 (Bridges) describes an electro thermal in situ energy storage for intermittent energy sources to recover fuel from hydro carbonaceous earth formations. Specifically, the '561 patent describes forming an opening in a formation, heating the formation with power from at least one source of intermittent electrical power provided through the opening, storing the thermal energy in the formation over a time interval sufficient to develop a recoverable fluid fuel, withdrawing valuable constituents from the formation via the opening, and varying the load on the power grid to at least partially compensate for the effects of the intermittent power changes on the power grid. Bridges specifically describes utilizing EM (electromagnetic) in situ heating methods in combination with in situ thermal energy storage to utilize large amounts of electrical energy from wind or solar power sources; and thereby avoid the CO2 emissions that conventional oil shale extraction processes generate. Bridges suggests that this combination has the potential to economically extract fuels from unconventional deposits, such as the oil shale, oil sand/tar sand and heavy oil deposits in North America. Bridges indicates that the described electro-thermal storage method can rapidly or smoothly vary the load presented to the power line, either ramping up the consumption or ramping down the load, thereby serving as a load leveling function. The variable loading function can be coordinated with reactive power sources to further stabilize the grid.
The present inventors appreciate that a need exists for improved processes for the production of shale oil, particularly for processes that rely upon increasingly scarce resources. For example, water that may be used during the course of an oil shale production cycle may be limited in availability due to more senior water rights and/or relatively low seasonal precipitation (and thus less available surface flows in nearby watersheds). In addition, a need exists for improved processes for producing hydrocarbons from an organic-rich rock formation, including, but not limited to oil shale, tar sands, and/or coal formations. For example, it is desirable to reduce the energy requirements for any operation associated with a heavy hydrocarbon resource and/or to utilize electrical power sourced from low GHG emission sources, such as wind power and/or solar power (solar cells, solar collectors, etc).
Even in view of currently available and proposed technologies, the present inventors have determined that it would be advantageous to have improved methods of treating subterranean formations to convert organic matter or mobilize heavy hydrocarbons into producible hydrocarbons. In addition, although Ljungstrom and/or Brandt discuss the use of intermittent power during off-peak periods, e.g., relying upon excess power from intermittent power sources, the present inventors have determined that there are additional ways to incorporate the use of intermittent, variable, and/or scarce production resources, such as intermittent electrical power and scarce process water, that will significantly reduce the environmental impacts and costs associated with oil shale production techniques discussed in the background art. Therefore, an object of this description is to provide one or more such improved methods. Other objects of this description will be made apparent by the following description of the description.